Fixed cutter drill bit for abrasive applications

ABSTRACT

The invention provides a fixed cutter drill bit for drilling through unconsolidated, highly abrasive formations. The bit includes a bit body having a cutting face and a side portion. The bit body comprising carbide matrix material. A plurality of blades azimuthally spaced about the cutting face and a plurality of cutters disposed along the blades. At least one gage pad is disposed along a side of the bit body and includes wear resistant gage elements formed of a material more wear resistant than the matrix material forming a portion of the gage pad. The wear resistant elements have a rounded surface and are embedded in gage pad material proximal a leading edge of the gage pad to provide a rounded wear-resistant edge or surface proximal the leading edge.

CROSS-REFERENCE TO RELATED APPLICATIONS

This patent application is a continuation of U.S. patent applicationSer. No. 11/367,097, filed Mar. 3, 2006 which claims priority to U.S.Provisional Patent Application Ser. No. 60/658,534, filed on Mar. 3,2005, which is incorporated herein by reference.

BACKGROUND OF INVENTION

1. Field of the Invention

The invention relates to fixed cutter drill bits designed for abrasiveapplications, and more particularly to fixed cutter bits designed forhigh rate of penetration drilling in unconsolidated ultra abrasiveformations.

2. Background Art

Different types of drill bits been developed and found useful indifferent drilling environments. Bits typically used for drillingboreholes in the oil and gas industry include roller cone bits and fixedcutter. Cutting structures on bits vary depending on the type of bit andthe type of formation being cut. Roller cone cutting structurestypically include milled steel teeth, tungsten carbide inserts (“TCIs”),or diamond enhanced inserts (DEIs). Cutting structures for fixed cutterbits typically include polycrystalline diamond compacts (“PDCs”),diamond grit impregnated inserts (“grit hot-pressed inserts” (GHIs)), ornatural diamond. The selection of a bit type and cutting structure for agiven drilling application depends upon many factors including theformation type to be drilled, rig equipment capabilities, and the timeand cost associated with drilling.

In drilling unconsolidated, ultra abrasive formations, bit life islimited due to excessive wear; therefore, bit cost has become asignificant factor in the selection of bits for this environment. Oneexample of an unconsolidated, ultra abrasive drilling applicationincludes drilling of the pay zone of heavy oil reservoirs. Heavy oilreservoirs typically comprise unconsolidated to low compressivestrength, yet highly abrasive sands that are permeated with thick, denseheavy oil. These dense, high viscosity liquid hydrocarbons are alsosometimes referred to as bitumen.

Heavy oil production typically requires special oil recovery techniques,such as the injection of heat and/or pressure into the reservoir toreduce the viscosity of the oil and enhance its flow. One commonly usedrecovery technique is known as steam-assisted gravity drainage (SAGD),which involves drilling a pair of horizontal wells, typically one abovethe other, through the reservoir as shown in FIG. 12, wherein the upperwell is used for steam injection into the reservoir and the lower wellis used to produce the heavy oil. This is further described in Curtis,et al., “Heavy-Oil Reservoirs”, Oilfield Review, Autumn 2002, pp. 50.

Horizontal wellbores drilled through heavy oil reservoirs often extend1000 meters or more through the reservoir. To maximize oil recovery in alarger reservoir, multiple directional wells may be drilled from acommon wellbore to reduce the distance the oil has to travel throughrock to reach a wellbore.

Drill bits used in unconsolidated, ultra abrasive applications aretypically damaged beyond repair after a first run due to the extremeabrasion and erosion encountered during drilling. Milled tooth rollercone bits have been considered the most economically feasible bit forthese applications because they cost significantly less than other bitsand offer more aggressive cutting structures for higher ROP. Fixedcutter bits are generally not used in these applications because theycost 5 to 10 times more than a comparable roller cone bit and typicallybecome damaged beyond repair after a first run, such that their highercost can not be justified.

Although roller cone bits have been found to be most economicallyfeasible for unconsolidated, ultra abrasive applications, the usefullife of these bits is limited. As a result, several bits are typicallyrequired to complete a wellbore and the trips back to surface to replacethe bits and the number of bits required to complete a well have asignificant economic impact on a drilling program. However, up to now,milled tooth bits have still been found to be more economically feasiblewhen compared to the significant cost of using a conventional fixedcutter PDC bit.

What is desired is a fixed cutter drill bit that offers increased usefullife in high ROP, unconsolidated, ultra abrasive applications. Inparticular, such bits may be useful in reducing the number of tripsrequired to complete wellbores in heavy oil drilling applications, orsimilar applications. Additionally, a drill bit capable of maintaininggage over an extended drilling operation in any highly abrasiveenvironment is desired. Also desired is a more abrasive resistant drillbit that may be used to achieve higher rates of penetration (ROP) toprovide a positive economic impact in a drilling program for a heavy oildrilling application.

SUMMARY OF INVENTION

In one aspect, the present invention provides a fixed cutter drill bitproviding improved performance in a high rate of penetrationunconsolidated abrasive drilling operation.

In one embodiment, the bit includes a bit body having a cutting face anda side portion. The bit body is formed of carbide matrix material. Aplurality of blades azimuthally spaced about the cutting face and aplurality of cutters disposed along the blades. At least one gage pad isdisposed along a side of the bit body and comprising wear resistant gageelements formed of a material more wear resistant than the matrixmaterial forming a portion of the gage pad. The wear resistant elementsinclude a rounded surface and are embedded in gage pad material proximala leading edge of the gage pad to provide a rounded wear-resistant edgeor surface proximal the leading edge.

In another embodiment, the drill bit includes a bit body, a plurality ofblades, and a plurality of cutters is disposed along the blades andarranged to have an extent from a corresponding blade front face of 0.10inches or less for a majority of the cutters. A majority of the adjacentcutters are also positioned to have spaces there between that are lessthan 0.25 inches. At least one gage pad is disposed along a side of thebit body. The at least one gage pad has a circumferential width that isat least about 2 inches or results in a total gage pad width equal to30% or more of the circumference of the bit. At least one wear resistantelement is disposed on the gage pad near a leading edge of the gage padto provide wear resistant protection near the leading edge.Additionally, the bit includes at least one back reaming elementpositioned on the bit to back ream formation in a path of the bit as thebit is pulled from a wellbore.

Various other aspects and advantages of the invention will be apparentfrom the following description and the appended claims.

BRIEF DESCRIPTION OF DRAWINGS

FIG. 1 shows is a perspective view of a fixed cutter drill bitillustrating general features of a bit.

FIG. 2 shows a plan view of a cutting face for a PDC bit in accordancewith one embodiment of the present invention.

FIG. 3 shows a perspective view of the cutting face of the PDC bit shownin FIG. 2.

FIG. 4A-4B shows wear marks on the blades tops of a PDC bit havingspiral blades after a drilling run in an unconsolidated, ultra abrasiveenvironment.

FIGS. 5A-5B show a close up view of a blade of a PDC bit used for adrilling run in an unconsolidated, ultra abrasive environment.

FIG. 5C shows a close up view of a blade on another PDC bit used for adrilling run in an unconsolidated, ultra abrasive environment, whereinthe blade spiral and spacing between cutters was reduced compared to thebit in FIGS. 5A-5B and resulted in reduced wear of matrix material fromaround the cutters.

FIG. 6A shows a cross section geometry of a conventional blade for a PDCbit.

FIG. 6B shows a cross section geometry of a blade for a PDC bit inaccordance with one embodiment of the invention.

FIG. 7A shows a blade top for a PDC bit without wear resistant materialembedded in its blade tops or cutter substrates after a first run in anunconsolidated ultra abrasive environment.

FIG. 7B shows a blade top for a PDC bit similar to the one shown in FIG.7A but with the addition of wear resistant material embedded in theblade tops and cutter substrates after a first run in an unconsolidatedultra abrasive environment.

FIG. 7C shows the condition of the blade top shown in FIG. 7B after fourbit runs.

FIGS. 8A-8C show a cutter oriented on a blade at a selected back rakeangle in accordance with one embodiment of the present invention.

FIG. 9 shows one embodiment of a novel abrasive resistant gage padconfiguration which may be used on a PDC bit in accordance with one ormore embodiments of the present invention.

FIGS. 10A-10B another embodiment of a novel abrasive resistant gage padconfiguration which may be used on a PDC bit in accordance with one ormore embodiments of the present invention.

FIG. 11 shows a partial view of a heel surface of a bit with backreaming elements positioned on the bit in accordance with an embodimentof the present invention.

FIG. 12 shows one example of a multi-well system used for Steam AssistedGravity Drainage recovery of heavy oil from a reservoir.

DETAILED DESCRIPTION

Reference will now be made to the figures in which various embodimentsof the present invention will be given numerical designations and inwhich aspects of the invention will be discussed so as to enable oneskilled in the art to make and use embodiments of the invention.

In one aspect, the present invention provides a fixed cutter drill bitfor drilling earth formations, which may be particularly useful indrilling formations comprising unconsolidated to low compressivestrength, yet highly abrasive sands, such as those encountered in heavyoil reservoirs. These types of formations will be generally referred toas “unconsolidated and ultra abrasive” for simplicity. In anotheraspect, the present invention provides novel gage pad configurations fordrill bits, which may be particularly useful on bits designed for anyabrasive drilling environment. In another aspect, the invention providesmethods for manufacturing or rebuilding fixed cutter bits.

Conventional PDC Bits

Fixed cutter drill bits (also referred to as fixed head bits or dragbits) are significantly more expensive than mill tooth roller cone drillbits and are considered to offer less aggressive cutting structures thanroller cone drill bits. However in several applications fixed cutterbits can be used to drill longer well segments in a single run and canbe rebuilt and reused multiple times to provide an overall economicbenefit that outweighs their higher cost.

Fixed cuter bits which include polycrystalline diamond compact (PDC)cutters are typically referred to as PDC bits. PDC bits can be rebuiltafter being used by heating the entire bit to a predefined hightemperature and then adding material to areas of the bit where materialhas been worn away due to erosion or abrasion. Material is typicallyadded by torch welding or the like. Additional heat may also be appliedto the cutting structure to melt brazed material around the cutters sothat cutters can be rotated to expose an unworn portion of the cuttingedge for drilling. When cutters cannot be rotated and reused due toexcessive damage or wear, cutters are removed and replaced with newcutters using additional braze material. Bit rebuilding operations aretypically carried out as quickly and carefully as possible out to avoidthermal stress cracks in the bit body material. Extensive rebuildoperations require repeated thermal cycling of the bit which leads to ahigher chance of forming thermal stress cracks. If thermal cracks arefound to have developed during a rebuild operation, the bit must bescrapped and a new bit used. Bits can only undergo a limited amount ofthermal cycling before developing thermal cracks. Therefore, thermalcycling during a rebuild operation should be limited when possible toextend the useful life of a drill bit.

When considering high rate of penetration (ROP), unconsolidated, ultraabrasive drilling applications, many PDC bits are not designed toprovide the ROPs demanded in these applications. PDC bits have also beenfound to suffer severe material loss in these unique drillingenvironments where unconsolidated ultra abrasive cuttings mix withdrilling fluid, often pumped at high flow rates, to Create a highlyabrasive/erosive slurry that flows around surfaces of the bit duringdrilling. The bit tends to ride on the abrasive slurry pumped betweensurfaces of the bit and the bottomhole, which results in excessive wearon the bit such that bits cannot be rebuilt or reused a sufficientnumber of times to justify their cost.

In particular, severe erosion has been found to occur between cutters,on cutter substrates, and on the blade faces around the cutters. Severeabrasion has also been found to occur across blade tops, cuttersubstrates, gage pad surfaces, and blade heel surfaces of the bit. Forexample, a conventional 12¼ matrix body bit may loose as much as 10 to12 pounds of material in a single run when used in an unconsolidated,ultra abrasive application. These bits typically cannot be rebuilt orrerun and must be scrapped. In a case where a bit may be rebuilt toattempt a second nm, the rebuild operations required are extensive andoften result in thermal stress cracks. Also, wear and damage sustainedby the cutters are usually such that the cutters cannot be rotated orreused for a second run.

In horizontal drilling applications, the gage pads suffer excessive weardue to constant rubbing action against the formation and the sharp sandsin the abrasive slurry flowing past gage pad surfaces. This can cause abit to go under gage prematurely. Conventional PDC bits also are oftenless directionally responsive than roller cone drill bits in theseapplications and have greater tendency to drill out of a desired zoneand into bounding formation without any indication at the surface. PDCbits also have gage surfaces that create multiple points of constanthole wall contact which results in bits going undergage prematurely inthese environments. Conventional PDC bits have also been found to bemore difficult to trip out of horizontal holes after completing theirdrilling requirement in these environments. This is because cuttingsthat fail to reach the surface during the drilling tend to fall to thelow side of the hole, effectively creating a restricted passage back tothe surface. Additionally, conventional PDC bits have been found to bemore susceptible to cutter damage when used to drill out cementing shoesand when engaging more competent formations above or below the reservoirpay zone. Damage sustained by conventional PDC bits in theseapplications leads to costly rebuild operations or the inability toreuse the bit. Thus, conventional PDC bits have not been economicallyfeasible unconsolidated, ultra abrasive drilling applications and aregenerally not used.

Fixed Cutter Bits for Unconsolidated, Ultra Abrasive Applications

The inventors have studied problems associated with the use of fixedcutter bits in unconsolidated, ultra abrasive drilling applications andhave discovered several design features that can be used tosignificantly extend the life of a fixed cutter drill bit in theseapplications to provide a positive economic impact on a drillingprogram.

Examples of the basic features on a PDC bit will now be generallydescribed with reference to the bit shown in FIG. 1. The drill bit 100includes a bit body 102 which has a central axis 104. The bit body 102has a connection 106 at one end for connecting to a drill string and acrown formed at the other end which includes a cutting face 103 forcutting through earth formation. A plurality of blades 108 are arrangedon the cutting face 103. The blades 108 are azimuthally spaced apart andextend radially and lateral along the cutting face 103. A plurality ofcutters 110 are mounted in pockets 109 formed on the blades 108. Thecutters 110 are typically attached to the blades 108 by braze materialor the like. The cutters 110 are generally arranged in rows along eachof the blades 108, with each cutter 110 mounted at a selected radialposition relative to the central axis 104 of the bit 100. The cutters110 are positioned and oriented on the blades to engage with earthformation as the bit 100 is rotated on earth formation under an appliedforce. The cutters 110 comprise a body of ultrahard material 111 bondedto a substrate 112 which is typically formed of less hard material.Transition layers may also be disposed between the ultrahard body 111and the substrate 112. The ultrahard body 111 is positioned to form thecutting face 111 for the cutters 110. The ultrahard body 111 typicallycomprises polycrystalline diamond (PCD), although other ultrahardmaterials known in the art may be used, such as cubic boron nitride. Inthe case of PCD, a region or the entire PCD body may be treated torender it thermally stable, such as by removing solvent metal catalystfrom a region or the entire body through a suitable process, such asacid leaching, aqua regia bath, electrolytic process, or combinationsthereof. One example of a suitable acid leaching method that may be usedis disclosed in U.S. Pat. No. 4,224,380, which is incorporated herein byreference. Alternatively, the PCD body may be formed using a catalyzingmaterial, such as silicon, that does not adversely affect diamond bondedgrains of the PCD body at elevated temperatures.

A gage region is also formed along an outer side surface 125 of the bitbody 102 and includes one or more gage pads 124 having surfaces thatextend proximal the gage diameter of the bit 100. One or more gageinserts 127 are embedded in material forming the gage pad 124 to contactthe side wall of the wellbore and help maintain the gage diameter beingdrilled. Gage pads 124 also help to stabilize the drill bit 100 againstvibration. In the example shown, a plurality of gage pads 124 are formedat the ends of blades 108 and are spaced apart around the periphery ofthe bit body 102 with junk slots 126 defined there between. Gage padswhich extend around the entire periphery of the body are also known inthe art and may be used.

A central longitudinal bore (not shown) which extends into the bit 100permits drilling fluid to flow from a drill string into the bit 100. Aplurality of openings or flow passages 118 are positioned in the cuttingface 103 of the bit 100 and in fluid communication with central bore.The flow passages 118 are configured for mounting nozzles 120 thereinwhich serve to distribute drilling fluid around the cutters 110 andcutting face 103 of the bit body 102. The nozzles direct fluid to flushformation cuttings away from the cutting structure and borehole bottomduring drilling. Grooves or channels 122 between the blades 108 serve asdrilling fluid flow courses for directing drilling fluid and cuttingsradially outward away from the cutting face 103. The junk slots 126between the gage pads 124 of the bit 100 are in fluid communication withthe channels 122 and permit drilling fluid and formation cuttings toflow away from the cutting face 103 and up an annulus formed between thedrill string and the wall of the borehole during drilling.

In this example, small hard elements 128 are also provided along on aheel surface 129 of the bit 100 to help “back ream” or remove formationin the path of the bit as the bit 100 is pulled from the borehole.

Matrix Body Bit

Features of embodiments of the invention will now be described withreference to FIG. 2. FIG. 2 shows one example of a cutting face designfor a drill bit in accordance with aspects of the present invention. Thebit body 202, blades 208 and gage pads 224 in this embodiment aregenerally formed of matrix material to provide greater abrasion anderosion resistance than conventional steel bodies. The matrix materialmay comprise tungsten carbide infiltrated with binder material. Thematrix bit may be formed in any conventional manner known in the art,such as by packing a graphite mold with a mix of tungsten carbide powderand then infiltrating the powder with a molten alloy binder in a furnaceand allowing it to cool to form a hard metal cast matrix body. Examplesof methods and materials for forming matrix body bits are furtherdescribed in U.S. Pat. No. 5,662,183, U.S. Pat. No. 6,287,360, and U.S.Pat. No. 6,375,706 which are all assigned to the assignee of the presentinvention and incorporated herein by reference. While reference is madeto tungsten carbide powder above, the powder may also include othermaterials, such as nickel, iron, cobalt, and/or other various alloys. Amatrix bit may be formed using other transition metal carbides, such asmolybdenum, niobium, tantalum, hafnium, and vanadium.

Ultrahard Cutters

Any cutters suitable for abrasive drilling applications may be used inaccordance with embodiments of the present invention. In the embodimentshown in FIG. 2, the cutters comprise a table or body of ultrahardmaterial 211 bonded to a substrate 212 of less bard material. Typicalcutters used are polycrystalline diamond compact (PDC) cutters, whereinthe ultrahard material 211 comprises a polycrystalline diamond table andthe substrate 212 comprises tungsten carbide. Other embodiments maycomprise cutters 210 formed of any ultrahard material and substratematerial suitable for drill bit cutters, including polycrystallinediamond, polycrystalline cubic boron nitride, tungsten carbide,combinations thereof, or other metal carbide.

PDC cutters can be formed by placing a cemented carbide substrate orcomponents for forming a carbide substrate into a press container. Amixture of diamond grains or diamond grains and catalyst binder is thenplaced on top the substrate and the container assembly is subjected tohigh pressure, high temperature conditions such that the metal bindermigrates from the substrate and through the diamond grains to promotebonding of the diamond grains to each other to form the diamond layer,subsequently bonding the diamond layer to the substrate. The catalyst orbinder material commonly used includes cobalt. The catalyst material maylater be removed or depleted from the working surface of the cutter forenhanced abrasion resistance. One or more intermediate layers ofmaterial may also be disposed between the diamond layer and thesubstrate, as is known in the art. Additionally, the cutter may includea non-planar interface between the diamond layer and substrate.

In one or more embodiments of the present invention, larger cutters areused on the bit to allow for higher rates of penetration. In one or moreembodiments, cutters having a diameter of 16 mm or larger are disposedalong the blades of the bit. For the example embodiment shown in FIG.5C, 16 mm and 19 mm cutters were used.

Cutter Placement

Many PDC bit designs have cutters spaced apart along the blades andpositioned to extend from a front of the blade front face. However,these cutter arrangements can lead to increased recirculation ofabrasive slurry around the cutters and blades and excessive abrasive anderosive wear on the cutters, blades, and braze material. Therefore, asshown in FIG. 2, cutters 210 are preferably placed closer together alongthe blades 208. By reducing the amount of space between adjacent cutters210 less abrasive slurry is allowed to flow between cutters and acrossthe blade tops 232, which can significantly reduce wear on the cuttingstructure.

Therefore, cutters 210 are preferably arranged on the blades 208 suchthat adjacent cutters on a blade 208 have a spacing there between of0.25 inches or less. In selected embodiments, this spacing may be closerto around 0.040 inches or less and may be applied to a majority ofadjacent cutters 210 on the blades 208 where possible. Arranging cutters210 closer together along the blades 208 also provides greater ultrahardcoverage along the leading edge of the blades 208 which leads to anoverall reduction of wear on cutters. Reducing the spacing betweencutters to 0.25 inches or less, and more preferably to 0.10 inches orless, can help reduce wear on the blade s 208 and the cutters 210, suchthat less material is lost from the bit during drilling. This can help abit effectively handle longer drilling runs and extend the useful lifeof the bit. In particular, this can reduce the time and number ofthermal cycles required for a rebuild operation.

In one or more embodiments, blades 208 of the bit 200 are alsopreferably formed to have a limited helix from cutter to cutter.Referring to FIGS. 4A and 4B, increased blade spiraling typicallyrequires that the cutters 710 be physically spaced further apart at thefront face 735 of the blades 708 due to space limitations at the basesof the cutters. Additionally, when a significant degree of spiral isapplied to cutters along a blade, wear occurs on the tops of the blades708. Corresponding spiraled wear grooves 761 have been found to formacross blades tops 732 due top abrasive slurry flowing in a spiraledpattern between cutters 710. This can also result in increased erosionon cutter substrate 712 for some bit designs By minimizing the helixspiral of the blades 708 or the cutters 710, cutters 710 can be spacedcloser together along the blades 708 to minimize erosive wear on thebit. Therefore, in one or more embodiments, a blade helix angle may belimited to 5° to allow for a closer spacing of cutters and to helpreduce wear on the bit. In other cases, helix angles may be limited to3° or less, and in some cases 1° or less may be preferred.

Referring again to FIG. 3, the inventors have also found that by placingcutters 210 on the blades 208 with a limited extension from a bladefront face 232 can also help to reduce wear on the cutting structure ofthe bit. By restricting the extent of cutters 210 from the blades 208 to0.10 inches or less, abrasive wear around the cutters 210 due torecirculation of the abrasive slurry can be reduced. In selectedembodiments, cutter extents of 0.06 inches or less may be used, and insome cases 0.03 inches or less may be preferred. In the embodiment shownin FIG. 3, the cutters are substantially flush with the blade front face235. In another embodiment, one or more of the cutters may be setrecessed from the blade front face.

Examples of test bits used for a drilling run in an unconsolidated,ultra abrasive formation are shown in FIGS. 5A-5C. FIG. 5A shows a closeup view of a first bit used, wherein adjacent cutters 810 were spacedfurther apart along the blade front face 835 than the cutters on asecond bit shown in FIG. 5C. The cutter spacing 859 for the bit in FIG.5A is partially due to an increased spiral of the blades 808 in thisdesign, as shown in FIG. 5B. The bit in FIG. 5C had substantiallystraight blades and a smaller spacing 859 between adjacent cutters 810.The cutter arrangement shown in FIG. 5A resulted in more matrix materialerosion on the front face 835 of the blades 808 below and between thecutters 810 than for the bit shown in FIG. 8C. Wear was also noted oncutter substrates 812. B reducing the helix and minimizing the amount ofspace between cutters, less abrasive flow was directed between andaround the cutters and wear on the cutting structure was reduced.

Thicker Blades and Gage Pads

In one or more embodiments, the bit also includes thicker blades andgage pads which may also help to increase the useful life of the drillbit in ultra abrasive applications. For example, referring to FIG. 3,the gage pads 224 in this embodiment are configured to span acircumferential width, w, of at least about 2 inches at a point alongtheir length. However, in other embodiments, gage thickness will dependon the number of gage pads in the bit design and the diameter of thebit. Therefore, in other embodiments, the gage pads may be arrangedaround the bit to provide a total width of gage surface around the bitthat is greater than or equal to 30% of the circumference of the bit.For example, a six blade, 12¼ inch diameter bit may be configured tohave six gage pads, each with a gage with, w, of between about 2 and 3½inches, such as around 2½ inches or more, resulting in a total gage padwidth of 15 inches or more which is around 39% of the circumference ofthe bit.

Space available for blade thickness is limited near the crown of the bit200.

However, in one or more embodiments, the blades 208 may be configured toincrease in thickness in a direction away from the center of the bit 200toward the gage pads 224. The blade thickness will generally depend onthe diameter of the bit 200 and the number of blades 208 in the bitdesign. Therefore, in one or more embodiments, the number of blades onthe bit maybe limited to eight blades or less, and in many cases sixblades or less to allow for thicker blades as well as higher ROPs.However, for the six bladed, 12¼ inch bit described above, the blades208 can be generally configured to increase in thickness along theirlength toward the gage region to a width close to the selected width ofthe gage pad.

In the embodiments shown in FIGS. 2 and 3, the blades supporting thegage pads 224 are formed continuous with the cutting structure blades(208). In other embodiments, space may be provided between the blades208 extending from the crown of the bit 200 and the blades or structuresupporting the gage pads 224 on the side of the bit body 202.Additionally, a bit may be configured to have a single gage pad thatextends around the periphery of the bit with junk slots provided betweenthe bit body and gage pads; however in many applications a bit having aplurality of gage pads spaced apart with substantially unrestricted junkslots there between may be preferred.

The inventors have determined that providing increased blade thicknesscan increase the number of rebuild operations a bit can undergo beforedeveloping thermal stress cracks. Thicker blades and gage pads have beenfound to retain heat better during rebuild operations such that morerebuild work can be done in a single heat cycle and the number ofthermal cycles required during a rebuild operation can be reduced.Additionally, blades and gage pads that are initially thicker thanstructurally required increase the chances of the bit being structurallysound for a second run before needing to be rebuilt. This can alsoreduce the time required for a rebuild operation because less materialwill need to be added to the bit to place it into a structurally soundrerunable condition. As a result, both the rerunability (ability torerun the bit) and the repairability (ability to repair the bit multipletimes) can be increased to enhance the economic feasibility of fixedcutter bits in unconsolidated, ultra abrasive drilling applications.

Referring now to FIG. 6A and 6B, in one or more embodiments, a drill bitmay also be configured to include a radius corner at the base of a bladebetween the blade and the bit body where thermal stresses tend to buildup during a rebuild operation. As shown in FIG. 6A, PDC bits may bedesigned to have a sharp corner at the blade base 634 where the bladefront faces 635 or blade back faces 637 join with the bit body 602. Whenthe faces are substantially perpendicular to the bit body, this isconsidered a 0° blade front face angle or blade back face angle. Highthermal stresses have been found to develop in these sharp cornersduring rebuild operations. Therefore, referring to FIG. 6B, in one ormore embodiments, a bit may be configured to have more rounded cornersat the base 634 of blades 608. For example, the blade front face 635and/or the blade back face 637 may be configured to have a larger bladefront face angle 636 and/or blade back face angle 638 so that a largerradius of curvature (655, 657) is formed at the base 634 of the blade608. Alternatively, the blades may be formed to include a desired radiusof curvature (655, 657), such as a radius of curvature of around 0.375inches or more. In one or more embodiments, bits may be designed to haveblade front angles 636 or blade back face angles 638 of 1° or more, andin some cases of at least about 5° or more. In one embodiment the bladeswere configured to have blade front face and back face angles of around10°. Providing a radius at the base of one or more blades can helpreduce the chance of developing thermal stress cracks in that areaduring repeat rebuild operations.

As shown in FIG. 6B, in some embodiments one or more of the blades 608may be configured to increase in thickness from the blade top 612 to theblade base 634 to provide a more robust blade for handling longer runsor a greater number of runs before needing to be rebuilt. Also, as notedabove, thicker blades have been found to retain heat better duringrebuild operations and may reduce the thermal cycling required torebuild a bit. This can also increase in the number of rebuildoperations a bit can undergo before developing stress cracks. In somecases, drill bits having blade tops that increase in width in a radialdirection toward gage and increase in width in an axial direction towardthe base of the blade may be desired for enhanced rerunability andrepairability in heavy oil drilling applications.

Increased Wear Resistant Surfaces

Additionally, in one or more embodiments, matrix materials used to formouter surfaces of the bit body, blades, and/or gage pads may be selectedto provide increased wear resistance over other matrix materialscommonly used for PDC bits in applications, such as high impactapplications. For example, matrix materials having a higher hardness orhigher carbide content may be used to provide increased wear resistance.Alternatively, the wear resistance of matrix material can be increasedby using more fine grain carbide powder to form the matrix. This canalso result in a higher carbide content and lower binder content whenthe matrix body is formed. For example, a tungsten carbide matrix powderused to form portions of the bit body, blades, and/or gage pads mayinclude a higher percentage of fine tungsten carbide particles toachieve an average tungsten carbide grain size of 60 μm or less, and insome cases 50 μm or less. Alternatively, the matrix powder used mayinclude at least about 30% by weight tungsten carbide with an averageparticle size between about 0.2 μm and 30 μm to provide a higher packingdensity to achieve increased wear resistance and strength. In selectedembodiments, this amount is at least about 40% by weight, and in somecases, at least about 50% by weight.

The wear resistance of matrix material can also be increased by using agreater amount of particular types of tungsten carbides to form thematrix powder. Types of tungsten carbides generally includemacro-crystalline tungsten carbide, cast tungsten carbide, carburizedtungsten carbide and sintered tungsten carbide. Matrix powders typicallyinclude two or more of the aforementioned types of tungsten carbidecombined in various weight proportions. Matrix powders may also includeother metal additives, such as nickel (Ni), iron (Fe), cobalt (Co) orother transition metals. The wear resistance of matrix material can beincreased by using a greater amount of a harder tungsten carbide in thematrix powder. For example, more cast carbide may be used in the matrixpowder. In selected embodiments, cast carbides in amounts of around 40%or more by weight, and in some cases 45% or more, have be used toprovide increased wear resistance over conventional matrix materials.

Additionally, in one or more embodiments, cutters used on the bit may beselected to have more wear resistant substrates. Wear resistance ofsubstrate material also increases with hardness or carbide content, orby decreasing the binder contents or tungsten carbide grain size.Therefore, in one embodiment, cutters with substrates having hardness of88 Ra or more may used Alternatively, cutters having substrates with abinder content of around 13% or less by weight may be used Also, in oneembodiment, substrates may be formed using tungsten carbide particleswith an average grain size of around 3 microns or less to provideincreased wear resistance. Alternatively, cutters 210 may be treated ora coating applied to exposed surfaces of cutter substrates to reducewear in selected embodiments.

Enhanced Wear Resistance Along Surfaces

To provide increased wear resistance along surfaces of the bit subjectedto the greatest amount of wear, selected portions on the bit, such asthe bit body 202, blades 208, or gage pads 224, may be formed usingdifferent matrix materials to obtain the increased wear resistancedesired without sacrificing impact toughness or crack resistance of thebit body. Examples of this are described in U.S. patent application Ser.No. 10/454,924 to Kembaiyan, titled “Bit Body Formed of Multiple MatrixMaterials and Method for Making the Same,” which is assigned to theassignee of the present invention and incorporated herein by reference.Referring to FIG. 3, for example, the blade tops 232 and surfaces of thegage pad 224 can be formed to include an outer layer of matrix materialhaving a higher wear resistance than an underlying layer which mayprovide higher toughness.

Additionally, ultrahard material can be deposited along surfaces of thebit body to reduce wear of matrix material in selected regions. Forexample, a coating comprising ultrahard material, such as a plateddiamond coating, may be applied to surfaces of the bit, such as alongthe blades 208, gage pads 224, or cutter substrates 212 to increase thewear resistance along those surfaces. Such coatings may be used to helpreduce wear on bit body surfaces and to allow for longer bit runs.

Alternatively, ultrahard particles or elements may be embedded in outersurfaces of the bit to increase the abrasion and erosion resistance ofthese surfaces. For example, ultrahard material can be embedded in bladetops and cutter substrates to further reduce wear during drilling. Testbits run in a high flow rate unconsolidated, ultra abrasive applicationboth with and without ultrahard material embedded in blade tops andcutter substrates are shown in FIGS. 7A-7C. The bit shown in FIG. 7A wasconfigured in accordance with aspects of the invention and used to drilla wellbore segment through a heavy oil reservoir with high drillingfluid flow rates. This bit did not include ultrahard material embeddedin the blade tops 532 or cutter substrates 512. As shown in FIG. 7A,when the bit was pulled to the surface after a first run, the bit wasfound to have reduced but noticeable wear across the blade tops 532 andexposed cutter substrates 512.

The bit shown in FIG. 7B has the same design as the bit in FIG. 7A butincludes the addition of ultrahard particles 542, 544 embedded along theblade tops 532 and in the cutter substrates 512. This bit was used undersimilar conditions substantially equivalent to the one shown in FIG. 7A.As shown in FIG. 7B, when the bit with ultrahard particles 542, 544embedded in therein was pulled to the surface after a first run,significantly less wear was found across the blade tops 532 and cuttersubstrates 512. The ultrahard particles used in this embodiment werenatural set diamonds, having grain sizes of around 1-3 mm or more (1-10stones per carat (“spc”) or less). A band of ultrahard material 545 wasalso embedded in the substrate material 512 behind the diamond table(ultrahard body 511) of the cutter, as further described in U.S. Pat.No. 6,272,753 to Scott, which is assigned to the assignee of the presentinvention and incorporated herein by reference. The addition ofultrahard material in the blade tops 532 and in the cutter substrates512 was found to significantly reduce the amount of matrix material lossfrom the bit during drilling.

FIG. 7C shows the condition of the bit in FIG. 7B after a fourth bitrun.

The blade tops 532 and cutter substrates 512 with the embedded ultrahardmaterial (542, 544, 546) were found to be in better condition than thebit run without embedded ultrahard material (shown in FIG. 7A). Addingultrahard elements in surfaces of the bit subjected to the highestamounts of wear may significantly reduce the amount of matrix materialworn from a bit in a given run and may also help to lengthen theeffective life of the bit in a drilling program.

In other embodiments where ultrahard particles or elements are embeddedor infiltrated into the matrix material forming surfaces of a bit, theultrahard material may be natural or synthetic diamond, or a combinationof both, and can be obtained in a variety of shapes and grades asdesired. Other ultrahard material particles or elements known in the artmay also or alternatively be used. In such cases, the matrix materialshould be selected to provide sufficient abrasion resistance so thatultrahard particles or elements are not prematurely released.

Along surfaces, such as the blade tops, larger ultrahard particles orelements can used, as desired, to allow for prolonged retention inmatrix material due to increased grip area around the particles formatrix material to hold them in place longer. For example, in selectedembodiments the blade tops and other surfaces on the bit can beimpregnated with diamond grit of any grain size. In one embodiment,diamond grit having a grain size of around 700 μm or more (150 spc orless) was used for prolonged resistance. In another embodiment, diamondgrit having a size of around 850 μm more (100 spc or less) were used.

Alternatively, ultrahard particles embedded in the matrix material maybe disposed both at and below the outer surface of the matrix materialfor prolonged abrasion resistance. Ultrahard particles infiltrated inmatrix material to a selected depth beneath surfaces of the bit may beprovided so that as the matrix material wears and ultrahard particles atthe surface fall out, additional particles will become exposed below thesurface for prolonged abrasion resistance. Bits having surfacesinfiltrated with ultrahard particles to a selected depth maintain theirability resist abrasion and erosion for longer periods of time, evenafter surface particles are worn down, which can also increase thelength or number of runs a bit can be used for before having to berebuilt.

Ultrahard particles or elements embedded in matrix material may also becoated to achieve a stronger bond in matrix material. Examples ofcoatings that may be used are described in U.S. application Ser. No.10/928,914 to Oldham, filed Aug. 26, 2004, titled “Coated Diamond forUse in Impregnated Diamond Bits,” assigned to the assignee of thepresent invention and incorporated herein by reference.

As noted, ultrahard elements formed of any abrasion resistant materialmay be embedded in the blade tops behind the cutters or along othersurfaces of the bit. Examples of ultrahard elements that may be usedinclude diamond grit-hot pressed inserts (GHIs), PCBN elements, and TSPelements. For example, GHIs or other elements containing abrasiveresistant material can be placed behind the cutters, such as similar tothat described for example in U.S. Pat. Nos. 4,823,892, 4,889,017,4,991,670 or 4,718,505. GHIs may be infiltrated or brazed into surfacesof the bit, as discussed in U.S. Pat. No. 6,394,202, to Truax andassigned to the assignee of the present invention.

A bit having selected surfaces impregnated with ultrahard particles orelements, as described above, can be formed by placing the ultrahardparticles or elements in predefined locations of a bit mold.Alternatively, composite components, or segments comprising a matrixmaterial infiltrated with diamond particles or the like can be placed inpredefined locations in the mold. Once the ultrahard material orcomponents are positioned, other components for forming the bit can bepositioned in the mold and then the remainder of the cavity filled withmatrix material, such as a charge of tungsten carbide powder. Finally,an infiltrant or binder can be placed on top of the matrix powder andthe assembly then heated sufficiently to melt the infiltrant for asufficient period to allow it to flow into and bind the powder matrixand segments. Using this process, a bit body that incorporates thedesired ultrahard particle containing sections and/or components can beformed.

As discussed above and shown in FIGS. 7B and 7C, ultrahard particles 544and/or ultrahard elements 546 (e.g., a band of ultrahard material) canalso be embedded in cutter substrates 512 for increased wear resistancealong an exposed portion of the substrate 512. Ultrahard particlesembedded in the substrate 512 or in matrix material surrounding thecutters may comprise particulate diamond or diamond grit, which may benatural or synthetic, or other ultrahard particles known in the art.Ultrahard elements used may comprise polycrystalline diamond (PCD),polycrystalline cubic boron nitride (PCBN), grit hot-pressed inserts(GHIs), or other ultrahard material elements known in the art.

Referring to FIG. 3, wear on cutter substrates 212 can also be reducedby limiting the amount of cutter substrate 212 exposed to abrasiveslurry during drilling. Therefore, in one or more embodiments, cutters210 with shorter substrates 212 may be used or the cutters 210positioned in the blade pockets 209 with less than the full length ofthe substrate exposed. For example, cutters may be positioned to haveexposed substrate lengths of 16 mm or less. In some cases, exposedsubstrates lengths may be limited to less than 13 mm, and in one or morecases, to 9 mm or less.

Cutting Arrangements

The cutters of the bit shown in FIGS. 2 and 3 are generally arranged ina short parabolic profile for to provide enhanced steerability forhorizontal drilling in unconsolidated, ultra abrasive formations. Thecutters are also arranged to minimize an imbalanced force on the bit anda difference in the work rates of the cutters. In other embodiments, anybit profile or cutter arrangement may be used.

The cutters can also be arranged at a back rake angle to provideenhanced steerability when desired for particular horizontal drillingapplications, such as for drilling the pay zone of a heavy oilreservoir. Cutters oriented with back rake provide a less aggressivecutting structure which may be more resistant to drilling out of the payzone of drilling heavy oil reservoirs which are typically bounded aboveand below by more consolidated formations. In particular, theresponsiveness of the bit to a formation change increases with back rakesuch that if a more competent formation is encountered during drillingthe bit will be more prone to skip or bounce along the boundingformation and remain in the desired drilling zone. Also cutters withhigher back rake are less likely to sustain damage when drilling floatequipment or a shoe in the path of the bit, such as at the start ofhorizontal drilling section. Providing a bit that is more sensitive toformation changes can also reduce drilling costs by obviating the needfor directional equipment in these applications. For unconsolidated,ultra abrasive applications, bits having higher back rakes may be usedbecause the rate of penetration of these bits is not a limiting issue inthese applications. Additionally, a bit's sensitivity to formationchanges may be further increased by using a short parabolic profilealong with increased back rake angles.

Orienting cutters at a back rake angle can also help reduce erosion oncutter substrates 212. For example, as shown in FIG. 8A, a cutter 910mounted on a blade 908 with zero back rake, is exposed to abrasiveslurry passing over the cutting edge of the cutter 910 during drilling.By orienting a cutter 910, as shown in FIG. 8B, at a selected back rakeangle 950, substrate exposure to abrasive slurry can be reduced andexposure of the ultrahard body 911 to the abrasive formation can beincreased. This may also increase the area in the blade pocket 909 forbonding cutters 910 to the blade 908. In selected embodiments, thecutters may be oriented with a back rake angle of 20° or more. In anembodiment similar to the one shown in FIG. 3, cutters have a back rakedistribution such that near the center of the bit are oriented with backrake angles of around 20° which increased towards gage to cuttersoriented with back rake angles of about 30° or more near gage.

In one or more embodiments, one or more cutters may be oriented at aselected a side rake angle. For example, cutters may also be oriented ata side rake angle toward the outside of the bit that is greater than 0°.Providing cutters oriented to include a side rake angle may helpincrease a bits resistance to drilling out of a desired formation zoneand may also help to direct abrasive cuttings away from the bit forenhanced cuttings evacuation and reduced wear.

Referring to FIG. 8C, cutters may also include a bevel or chamfer 990that extends from a periphery of the top surface 991 of the ultrahardbody 911 to the sidewall 992 of the ultrahard body 911. The chamfer 990may extend about the entire periphery of ultrahard body 911, or onlyalong a periphery portion adjacent the formation to be cut. Chamfers maybe any size and different sized chamfers may be used in differentlocations on selected embodiments. In selected embodiments similar tothat shown in FIG. 2, cutters having chamfer lengths of 0.012 inches(measured along the side of the cutter) oriented at around 45° (withrespect to the side of the cutter) were used for enhanced impactresistance. In selected embodiments, cutters with larger bevels may beused, such as for drilling through shoes and equipment in a wellbore.For example, cutters having a bevel size greater than or equal to 0.025inches may be used.

Improved Gage Protection

When conventional fixed cutter bits are used in unconsolidated, ultraabrasive applications they suffer excessive wear along the gage pads dueto rubbing action against the formation and abrasive slurry flowing pastgage surfaces. Therefore, in accordance with embodiments if the presentinvention, a fixed cutter drill bit for unconsolidated, ultra abrasiveenvironments also includes wear resistant elements, such as diamond orultrahard material containing elements, embedded in gage pad surfaces toprovide enhanced wear resistance at gage.

For selected embodiments, especially those designed for long runs inhigh flow rate directional drilling applications, additional gage padprotection may be required. In these applications, abrasive slurrycontaining sharp sands tends to abrade matrix material along the leadingedge which exposes inner regions of the gage pad to a greater amount ofabrasive wear. As a result, matrix material around the wear resistantelements in the pad may eventually become worn away causing the wearresistant elements to fall out.

Therefore, in selected embodiments, wear resistance of a gage pad may beincreased by placing wear resistant elements proximal a leading edge ofthe gage pad to serve as a barrier to abrasive slurry impacting theleading edge. Wear resistance may also be increased by providing agreater amount of diamond coverage on the gage pad. This is done byusing larger wear resistant elements with longer substrates orextensions for embedding into the matrix material to increase theability of the gage pad to retain the wear resistant elements duringdrilling.

One example of a novel abrasive resistant gage pad arrangement that maybe used on an embodiment of the invention described above to enablelonger drilling runs or on any PDC bit for enhanced abrasive resistanceis shown in

FIG. 9. In this embodiment, the gage pad 1224 includes wear resistantelements 1227 which are embedded in the gage pad material 1275. The gagepad material 1275 comprises a carbide matrix, such as tungsten carbideinfiltrated with binder material. A number of the wear resistant 1227elements are embedded in the matrix material close to the leading edge1270 of the gage pad 1224. The wear resistant elements 1227 disposedproximal the leading edge 1270 are positioned around ¼ inch or less awayfrom the leading edge 1270 and arranged span a majority of the length ofthe leading edge 1270. A plurality of the wear resistant elements 1227are also disposed along a tailing edge 1272 of the gage pad 1224 andalong a top edge 1273 and a bottom edge 1274 of the gage pad 1224 toprovide enhanced wear resistance along these edges. Wear resistantelements 1227 positioned near the trailing edge 1272 are positionedaround ¼ inch or less away from the trailing edge 1272 and span amajority of the length of the trailing edge 1272. A plurality of thewear resistant elements 1227 are also provided in the interior region ofthe gage pad to provide a large amount of overall wear resistantcoverage on the gage pad 1224.

The wear resistant elements 1227 in the embodiment shown in FIG. 9include large wear resistant elements 1277 and smaller wear resistantelements 1276 positioned around the large wear resistant elements 1277.The larger elements 1277 provide larger bearing surfaces to helpmaintain gage and include longer substrates that are embedded deeperinto the gage pad material 1275 for increased retention. The smallerwear resistant elements 1276 are positioned around the larger wearresistant elements 1277 for increased wear resistant coverage.

In the embodiment shown, the larger wear resistant elements 1277comprise diamond enhanced inserts (“DEIs”) which include a layer ofpolycrystalline diamond material bonded to a substrate. The DEIs arearranged in three rows which generally spanning the length of the gagepad. Five DEIs are disposed in the rows closest to the leading edge andthe trailing edge. Four DEIs are positioned in the interior region ofthe gage pad. The DEIs used on selected bits may have diameters of 13 mmor more to provide larger bearing surface areas of greater than 130 mm²,and may include substrates having lengths of 9 mm or more to allow forgood retention during drilling. The substrate end of the DEI is embeddedin the matrix material 1275 with the top surface of polycrystallinediamond exposed at the gage pad surface for contact with abrasive slurryand the walls of the wellbore. In other embodiments, DEIs or other largeinserts having super abrasive resistant bearing faces of any size may beused in any arrangement desired. In another example, 16 mm or larger DEIinserts are used proximal the leading edge 1270 which act as largerbarriers for abrasive slurry passing over the leading edge to helpreduce wear of matrix material from around other wear resistant elementson the gage pad behind the leading DEIs. Also, in other embodiments,DEIs may be arranged in three or more rows or with 3 or more DEIs withina one inch length of the gage pad.

The smaller wear resistant elements 1276 comprise thermally stablepolycrystalline diamond (TSP) elements embedded in the gage pad material1275. The gage pad material 1275 comprises a metal carbide matrixmaterial. In selected embodiments, the gage pad material 1275 may alsobe impregnated with or coated with ultrahard particles, such as diamondgrit, to further increase abrasion resistance. In other embodiments,wear resistant elements of any type, number, shape, or size may be used.

For the embodiment shown in FIG. 9, the combination of larger andsmaller wear resistant elements 1277, 1276 near leading and trailingedges of the gage pad provide a total diamond (or similar wear resistantelement) coverage along each edge that is greater than 75% of the lengthof the gage pad and closer to 100%. Additionally, close to 50% or moreof the gage pad surface comprises diamond. Using larger super abrasiveresistant elements with longer substrates near the leading edge of thegage pad reduces wear of matrix material from the gage pad surface suchthat smaller elements disposed on the gage pads are retained longerduring drilling. This will also reduce the amount of material lost fromthe gage pad during drilling, which will reduce the amount of time andenergy required to rebuild the bit

Another example of a novel gage pad layout that may be used forembodiments of the inventions to permit longer drilling rims in abrasiveapplications is shown in FIGS. 10A and 10B. This gage pad arrangementmay also be used for on any bit for enhanced gage protection. In thislayout, wear resistant elements are positioned to provide a rounded edge(or surface proximal the edge) on the gage pad which is more resistantto sharp sands in abrasive slurry than the gage pad matrix material.

Referring to FIG. 10A, in accordance with this layout, the gage pad 1324of the bit is formed of matrix material 1375, such as tungsten carbideinfiltrated with binder material. Wear resistant elements 1378 havingrounded or convex surfaces are embedded in the matrix material 1375proximal the leading edge 1370 of the gage pad 1324 such that they areor may eventually become exposed at the leading edge 1370 duringdrilling to provide a rounded and super abrasive resistant edge on thegage pad 1324. Wear resistant elements 1378 having rounded or convexsurfaces are also embedded in the matrix material 1375 proximal thetrailing edge 1372 of the gage pad 1324 such that they are or mayeventually become exposed at a trailing edge 1372 during drilling toprovide a rounded and super abrasive resistant trailing edge for thegage pad 1324.

In the example shown, the wear resistant elements 1378 positionedproximal each edge of the gage pad 1324 are axially aligned andgenerally arranged end to end along each edge to provide rounded,substantially continuous, and wear resistant edge portions for the gagepad 1324. Small spacing may be provided between the ends of adjacentwear resistant elements 1378 with matrix material disposed there betweenfor enhanced retention of the elements 1378 embedded in the matrixmaterial.

A cross section of the gage pad in FIG. 10A, taken along line A-A, isshown in FIG. 10B. As shown in FIG. 10B, the wear resistant elements1378 positioned proximal the leading edge 1370 and the trailing edge1372 of the gage pad 1324 may be cylindrical in form with axes generallyparallel to the leading or trailing edge. The wear resistant elements1378 are at least partially embedded in matrix material 1380 forming thegage pad 1324. When exposed near a leading or trailing edge 1370, 1372of the gage pad 1324, the wear resistant elements 1378 provide a roundedand super abrasive resistant edge surface which results in a smotherflow of abrasive slurry around the edges of the gage pad andsignificantly reduces wear of material from interior gage pad surfaces.This arrangement also provides a gage pad that is able to retain bothedge and interior wear resistant elements 1378, 1379 longer duringdrilling.

Wear resistant elements 1379 disposed along in the interior region ofthe gage pad 1324, between the leading edge 1370 and trailing edge 1372,are arranged along the gage pad 1324 to provide super abrasive bearingsurfaces for maintaining gage during drilling. In this example, interiorwear resistant elements 1379 are generally cylindrical in form withtheir linear axes generally perpendicular to the outer surface of thegage pad. As shown in FIG. 10B, these interior elements 1379 areembedded in matrix material 1375 forming the gage pad 1324 and have aflat or generally convex end surface exposed along the surface of thegage pad for bearing engagement with. wide walls of a wellbore duringdrilling. In this embodiment, the wear resistant elements 1379 aregenerally arranged in a row along the length of the gage pad 1324. Thegage pad 1324 is also slanted or spiraled such that it has helix anglewith respect to the bit axis (not shown). Spiraling the gage pad 1324provides increased surface area for the gage pad (for a given gagewidth). Aligning the row of wear resistant elements 1324 generallyparallel to the leading edge of the gage pad allows for the placement ofmore wear resistant elements along the gage pad length, which can resultin enhance gage pad protection and drilling life for the bit. However,in other embodiments, any shape or type of gage pad may be used and mayinclude any type, number, size, shape, or arrangement of wear resistantelements to help maintain gage.

In one example, the wear resistant elements 1378 disposed along theleading edge 1370 and trailing edge 1372 of a gage pad are diamond grithot-pressed inserts (GHIs), which may be infiltrated or brazed into gagepads of a bit, such as the one shown in FIG. 3. GHIs are diamondimpregnated elements which can be manufactured by placing a mixture ofdiamond particles and powdered matrix material in a mold. The contentsof the mold are then hot-pressed or sintered at an appropriatetemperature, such as between about 1000 and 2200° F., to form acomposite diamond-impregnated insert. The diamond particles used may benatural or synthetic and may be obtained in a variety of shapes andgrades. In the example, six GHIs are disposed proximal the leading andtrailing edges of the gage pad and provide substantially 100% superabrasive coverage along most of the length of the leading and trailingedges. The GHIs may have diameters of up to 13 mm or more and may alsohave lengths of up to 13 mm or more. In other embodiments, wearresistant elements 1378 positioned to form at least part of the leadingedge 1370 or at least part of the at the trailing edge 1372 duringdrilling may comprise any size, shape or type of super abrasiveresistant elements known in the art, including GHIs, PCD elements, TSPelements, polycrystalline cubic boron nitride (PCBN) elements, or thelike or combinations thereof.

In the example noted, the interior wear resistant elements 1379positioned along the interior surface of the gage pad 1324 comprise DEIswith carbide substrates. The carbide substrates are embedded into thegage material with the diamond tables exposed at the surface of the gagepad. The DEIs have diameters of up to 13 mm or more with lengths,including substrates, of up to 9 mm or more. In some cases, DEIs havingdiameters of 16 mm or more and/or substrates of 13 mm or more are used.In other embodiments, wear resistant elements of any type, number,shape, size, or combination may be used in interior regions of the gagepad, including DEIs, PCD elements, TSP elements, PCBN elements, GHIs, orthe like or combinations thereof.

Additionally, the gage pad material 1375 may comprise a harder matrixmaterial than that used to form another part of the bit body asdescribed in relation to other aspect of the invention above.Alternatively or additionally matrix material forming part or the entireouter surface of the gage pad may be impregnated (or coated) withultrahard particles, such as diamond grit, to provide increased abrasionresistance for the gage pad. For example, as shown for the gage padlayout in FIG. 10B, the outer surface of the gage pad may include alayer of matrix material impregnated with diamond grit 1381 formed onother matrix material 1380 forming part of the gage pad. This may beachieved by packing surfaces in a bit mold which form the gage pad withimpregnated material before filing the mold with other matrix materialused to form the bit.

In one example, diamond grit having a grain size of around 700 μm ormore (150 spc or less) was used to form diamond impregnated surfaces ofa gage pad having a similar layout to the one shown in FIGS. 10A and10B, with 13 mm GHIs used proximal the leading and trailing edges of thegage pad and 13 mm DEIs used along the interior gage pad surface. Inanother example, diamond grit having a size of around 850 μm more (100spc or less) was used. In one or more embodiments, the combination oflarger wear resistant elements and diamond impregnated matrix materialcan be used to provide substantially 100% abrasive resistant coverage onthe gage pad surface to minimize exposure of underlying matrix materialto eroding slurry in ultra abrasive applications. This gage padcombination was used on the bit shown in FIG. 7B and was found to beparticularly effective when performing longer drilling runs and/ormultiple drilling runs in unconsolidated ultra abrasive formations.

Additionally, the gage pads of the bit may be configured as replaceablegage pads as is generally know in the art with the gage pad layoutsdesigned in accordance with examples given above. In the case ofreplaceable gage pads, the gage pads and corresponding bit surface mayinclude complementary securing elements which mutually engage oneanother and the gage pad removably secured to the bit body by brazing,mechanical locking, or the like. Removable gage pads may be used tofacility faster rebuild operations.

In general, it has been found that having rounded wear resistantelements positioned proximal the leading edge of a gage pad cansignificantly reduce wear on gage pad surfaces and increase bit life,especially in ultra abrasive applications. This can also reduce the timeand materials required to repair a bit. Also, using GHIs or similarelements may permit the use of larger wear resistant elements alongedges of the gage pad and may also result in increased elementretention. Using DEIs with longer substrates permits deeper grip in thegage pad material for increased retention. Additionally, the use ofmatrix material impregnated with ultrahard particles along the outersurface of the gage pad can help to further reduce wear on the gage padsand increase bit life, especially for bits used in ultra abrasiveenvironments.

Back Reaming Features

Referring to FIG. 11, one or more embodiments additionally includes atleast one back reaming element 1428 positioned on the bit to “back ream”or remove formation in the path of the bit as the bit is pulled from aborehole. The back reaming element 1428 may comprises a PCD cutter orsimilar shearing element that is preferably positioned to minimizecontact with formation during drilling yet positioned to effectivelydrill through formation in the path of the bit as the bit is pulled outof the wellbore. For example, referring to FIG. 3, back reaming elements(not shown) may be positioned along heel surfaces 229 blades at the side225 of the bit that support gage pads 224.

FIG. 11 shows an enlarged partial cross section view of a heel surface1429 of a bit 1400 in accordance with an embodiment of the presentinvention. The bit 1400 generally comprising a bit body 1402 having acentral axis 1404, a connection formed at one end (generally indicated),and a cutting face disposed at another end (general indicated). The bit1400 also includes one or more gage pads 1424 disposed about a sidesurface 1425 of the bit 1400. Back reaming elements 1428 are generallypositioned along a heel surface 1429 of the blades supporting the gagepad 1424.

Back reaming capability is particularly desired for embodiments of theinvention designed for horizontal drilling because cuttings tend to fallto the low side of the hole during drilling such that when the bit isretrieved from the borehole it typically has to plow through cuttingsbuilt up on the low side of the hole so that the bit can be removed.Because back reaming elements may have to do a lot of work in theseapplications, larger back reaming elements and/or a plurality of backreaming elements may be used to provide increased cutting capability andabrasion resistance along heel surfaces of the bit.

In selected embodiments one or more back reaming elements 1428positioned on a heel surface 1429 of the bit may comprise a largerelement, such as PDC cutters (or similar elements) having a diameter ofabout 13 mm, or more. Alternatively, in one or more other embodiments,at least two back reaming elements 1428 are disposed along selected heelsurface of the bit to provide efficient removal capability for the bitwhen pulled out of the hole. The number and/or size of the back reamingelements on each heel surface may be selected to provide a particularamount of diamond coverage. For example, two or more 16 mm back reamingcutters or cutters of any size may be positioned along heel surfaces ofeach gage pad blade to provide diamond coverage of greater than 300 mm²along each of the heel surfaces. Providing good back reaming capabilityon selected embodiments used for directional drilling eliminates issuesof the bit getting stuck in the hole and excessive wear on the heelsurfaces of the bit that must be addressed in rebuild operations.

In other embodiments, a back reaming element may comprise any type ofactive cutting structure known in the art including a PCD compact, aPCBN compact, a diamond impregnated insert, and natural diamondelements. PDC back reaming elements have been found to be particularlyeffective in maintain gage all the way in horizontal, unconsolidated,ultra abrasive applications. PDC elements having longer substratelengths also permit deeper penetration of the substrate into the bladematrix material for greater retention of the cutter.

In alternative embodiments, back reaming elements positioned on the bitmay comprise different types of cutting elements, such as TSPs and GHIsor PCD compacts. Additionally, cutter types may be arranged to alternatealong heel surfaces as desired. Heel surfaces of the bit may also becoated with hardfacing material or impregnated with wear resistantmaterial, such as diamond particles or other wear resistant material, tofurther reduce wear on the heel surfaces that occurs as bits are removedfrom longer bit runs.

Hydraulic Considerations

In one or more embodiments, to reduce erosive wear, particularly in highflow rate drilling in unconsolidated, ultra abrasive applications fluidpassageway may disposed between the blades may be oriented to directmore of the drilling fluid toward a corresponding junk slot of the bitrather than directly on the cutters. The bit 200 shown in FIG. 2includes fluid passageways 218 which are generally disposed between eachof the blades 208 to wash cuttings from the cutters 210, blades 208 andbottomhole of a wellbore. Fluid passageways 218 are generally orientedat skew angle selected to direct drilling fluid and cuttingssubstantially parallel to or somewhat away from blade front surfaces toreduce the impingement and velocity of abrasive slurry flowing over theblades 208 and cutters 210. Fluid passageways 218 are also generallyoriented with a profile angle that more directs abrasive slurry up thejunk slots 226 of the bit rather than for impingement on the bottomholeto help reduce recirculation of abrasive slurry around the bit 200during drilling. This can also help to prevent over the washing sandsand the like from the bottomhole during drilling.

Other design considerations may also be used to reduce the velocity orimpingement of the abrasive slurry on the bit body. For example, in oneor more embodiments, one more diffuser nozzles may be used to reducefluid velocities around the cutters to help reduce erosive wear on thecutting structure during drilling. Alternatively, in one or moreembodiments, a bit may be designed to include more nozzles 220 thanblades 208 to help lower the concentration of hydraulic energy acrossthe cutting face of the bit. Alternatively, a bit may be designed withan increased total flow area, such as by configuring the one. or more ofthe passageways 218 or nozzles 220 to have a larger than normal exitport.

Braze Material

Braze material is typically selected for highest braze strength;however, braze strength is not considered a limiting factor in manyunconsolidated, ultra abrasive applications. Therefore, in one or moreembodiments, a more viscous braze material may be applied between thecutters and the cutter pockets to increase the reusability of cuttersand reduce the cost associated with rebuilding the bit. A more viscousbraze material may be used so that when a cutter substrate is slightlyeroded or has minor nicks on the exposed portion of the substrate, thecutter can be spun during the rebuild operation to coat the substratewith the thicker braze material to fill the small voids or wear marksand provide sufficient adhesion for subsequent runs.

Therefore, in selected embodiments, a braze material which is or can bekept more viscous during the brazing process may be used to bond one ormore of the cutters into the cutter pockets on the blades, especially inlocations where erosion of the brazed joint or carbide cutter substratehas been observed or predicted. The more viscous braze material can beselected from alloys having a larger difference between the liquidus (L)and solidus (S) temperatures. For example, the commercial braze alloyBAg7 (L=652° C., S=618° C.), may be selectively replaced with BAg18(L=718C, S=602C) or other silver-based alloys. The alloys may includecombinations of small percentages of metallic or transitional elements,or of non-melting elements or refractory particles, which may increasethe effective viscosity while brazing. The brazing process can also becontrolled to use lower temperatures, which also increases effectiveviscosity. For example, a braze materials having a larger differencebetween the liquidus and solidus temperatures can be used to brazecutters at a temperature between the liquidus and solidus temperature,such as around midway between the range, so that the braze materialremains more viscous during the brazing process.

Also, in one or more embodiments, a hardfacing overlay coating may beapplied to portions of the bit, such as exposed surfaces of brazematerial to minimize erosion of braze material around the cutters duringdrilling, as discussed for example in U.S. Pat. No. 6,772,849 to Oldhamet al., titled “Protective overlay coating for PDC drill bits” disclosesa method of increasing a durability of a PDC drill bit by overlaying atleast a portion of the exposed surface of the braze material between thecutter and the cutter pocket with a hardfacing material.

Other Embodiments

Those skilled in the art will appreciate that selected featuresdescribed above may be combined in various ways as desired for a giveapplication to provide a PDC drill bit capable of drilling longerwellbore segments through abrasive or ultra abrasive formations. It willalso be appreciated that in the case of PDC elements or cutters providedon the cutting face of the bit as referenced above, all or a portion ofthe diamond layer may be leached or otherwise treated to provideincreased abrasion resistance.

Bits in accordance with one or more embodiments of the present inventioncan be used to drill an entire horizontal segment through the pay zoneof a heavy oil reservoir, which may extend 1500 meters or more inlength. Selected embodiments may provide a drill bit capable of drillingmultiple horizontal segments before having to be pulled to the surfaceand rebuilt. For example, a drill bit may be used to drill a firsthorizontal leg through a heavy oil reservoir and then side tracked todrill another horizontal leg without having to be pulled back tosurface. A drill bit able to drill multiple lateral wells can provide asubstantial time and cont savings to a drilling operation. A PDC bit mayalso include larger cutters such as 16 mm cutters or larger to providehigher ROP as well as durability in drilling heavy oil reservoirs.

In one or more embodiments, erosion between cutters may be reduced byreducing cutter separation distances along surfaces of the bit. In oneor more embodiments back reaming capability may be improved by placinglarger cutters or a larger number of cutters along heel surfaces of thebit to minimize blade upside wear. Additionally, in one or moreembodiments a PDC drill bit may include larger beveled cutters orientedat a back rake for enhanced steerability and/or to help minimize impactdamage that can result from drilling out equipment in the wellbore orcontacting harder formation stringers that dip into a drilling zone.

In accordance with one or more embodiments erosion on cutter substratesmay be reduced by limiting the amount of substrate material exposed tothe formation, by placing cutters at higher back rake, and/or byminimizing spacing between cutters. In one or more embodiments, erosionmay be reduced around the cutters by placing PDC cutters substantiallyflush with the blade face and by providing cutter arrangements that donot include additional gaps or spaces, such as cutter pocket reliefgrooves. Erosion and abrasion may also be reduced by directing fluidnozzles towards the center of fluid channels or slightly away from thecorresponding blade front face. Also, in one or more embodiments bladeshaving limited helix may be used and/or and with diamond imbedded in theblade tops and/or cutter substrates to reduce wear behind the cuttersand across the blade tops.

Additionally, a novel gage pad configuration may be used on any bit tominimize gage pad wear. Additionally, using gage pads with largersurface area, such as wider or more spiral gage pads, may help maximizediamond coverage on the gage of the bit. In one or more embodiments, thediamond coverage on a gage pad may be 35% or more, and in some cases 50%or more. In one embodiment a gage pad may comprise five or more gage padelements with diameters of 13 mm or more arranged in a row along thegage pad. In another embodiment, a gage pad may comprise seven or moregage pad elements having diameters of 13 mm or more. In one or moreembodiments, larger wear resistant elements, such as GHIs, DEIs orultrahard compacts, may be placed closer to the leading and/or trailingedges of the gage pads to reduce gage pad wear. Wear resistant elementshaving rounded surfaces may be disposed proximal the leading edge of thegage pad to provide a rounded edge resistant to sharp sands in theabrasive slurry to help maintain the leading edge longer. Wear resistantelements disposed in the gage pad may be infiltrated or brazed into thegage pad. In one or more embodiments, impregnated diamond grit may beused to form surfaces of the bit, such as part of the gage pad and/orblade tops to provide increased abrasion resistant for extended bitlife.

In other embodiments, a coating may also be applied to surfaces of thebit to provide increased abrasion resistance. For example, CVDtechnology or other coating technology may be applied to coat leadingedges or surfaces of the gage pad. PDC bits having enhanced gagefeatures in accordance with one or more embodiments of the presentinvention may be able to effectively resist going under gage duringextended drilling runs, which minimizes the risk of compromising theeffective diameter of the wellbore and subsequent operationalcomplications.

One or more embodiments, a PDC bit having cutters closely spaced,limited blade helix, natural diamond embedded in blade tops, roundedwear elements disposed along leading and trailing edges of the gage pad,and impregnated diamond in the gage pad may be used to provide aneconomic benefit to a high ROP, heavy oil drilling program.

PDC bits including selected features described above may be rebuilt andreusable a sufficient number of times to provide a positive economicimpact to an overall drilling program in unconsolidated, ultra abrasiveformations and similar formations. Such bits may also make it possibleto drill longer horizontal segments in these environments without havingto pull a bit to the surface.

While the invention has been described with respect to a limited numberof embodiments, those skilled in the art will appreciate that numerousother embodiments can be devised which do not depart from the scope ofthe invention as set forth in the appended claims.

1. A drill bit for drilling through an earth formation comprising: a bitbody having a cutting face and a side portion, the bit body comprisingcarbide matrix material; and a plurality of blades azimuthally spacedabout the cutting face; wherein at least one of the plurality of bladesis configured such that at least a portion of said blade has a widerblade base than a blade top in the axial direction and at least aportion of the surface of said blade top comprises an ultrahard materialimpregnated therein.
 2. The drill bit of claim 1, wherein said bladeincreases in thickness in a radial direction away from the center of thebit body.
 3. The drill bit of claim 1, wherein each of the plurality ofblades is configured along a portion thereof to have a wider blade basethan a blade top.
 4. The drill bit of claim 1, wherein said portion ofsaid blade has a blade front face angle or a blade back face anglegreater than about 5°.
 5. The drill bit of claim 1, wherein said portionof said blade has a blade front face angle or a blade back face angle inthe range of from about 5° to about 10°.
 6. The drill bit of claim 4,wherein said portion of said blade has a blade front or back face radiusof curvature of least about 0.375 inches.
 7. The drill bit of claim 1,wherein said portion of said blade has a blade front or back face radiusof curvature of least about 0.375 inches.
 8. The drill bit of claim 1,wherein the bit body further comprises at least one gage pad disposedalong a side of the bit body and at least a portion of the bit body orat least one gage pad is coated with ultrahard material or comprisesultrahard material embedded in a surface thereof.
 9. The drill bit ofclaim 1, where the ultrahard material comprises diamond grit impregnatedin the blade surface.
 10. The drill bit of claim 9, wherein theultrahard material further comprises surface set diamonds embedded inthe blade tops.
 11. The drill bit of claim 10, wherein the ultrahardmaterial comprises diamond grit having a grain size of at least about700 μm or more and natural diamond having a grain size in the range offrom about 1 mm to about 3 mm.
 12. The drill bit of claim 1, wherein theultrahard material comprises diamond grit having a grain size of atleast about 700 μm or more.
 13. The drill bit of claim 1, wherein theultrahard material comprises diamond grit having a grain size of atleast about 850 μm or more.
 14. The drill bit of claim 1, wherein theultrahard material comprises polycrystalline diamond.
 15. The drill bitof claim 1, wherein said blade further comprises a first matrix materialand a second matrix material wherein the first matrix material has adifferent wear resistance that the second matrix material.
 16. The drillbit of claim 1, wherein the matrix material comprises tungsten carbidepowder having an average grain size of about 60 μm or less formed with ametallic binder.
 17. The drill bit of claim 1, wherein the matrixmaterial comprises a matrix powder including at least about 40% byweight tungsten carbide having an average particle size of between about0.2 and 30 μm formed with a metallic binder.
 18. The drill bit of claim1, wherein the matrix material comprises cast carbide in an amount of atleast about 40% or more by weight.
 19. The drill bit of claim 1, whereinthe drill bit further comprises a plurality of cutters disposed along atleast one of the plurality of blades.
 20. The drill bit of claim 19,wherein selected cutters have a back rake angle of at least about 20°.21. The drill bit of claim 20, wherein selected cutters have a back rakeangle is at least about 30°.
 22. The drill bit of claim 21, where thecutters increase in back rake angle from around 20° to about 30° or morealong a profile of the bit toward gage.
 23. The drill bit of claim 19,wherein cutters proximal a gage region of the bit have a back rake anglegreater than the back rake angle of cutters near a center of the bit.24. The drill bit of claim 19, wherein selected ones of the cutters havea side rake angle of greater than 0° degrees.
 25. The drill bit of claim19, wherein the cutters on the bit are arranged in a short paraboliccutting profile.
 26. The drill bit of claim 19, wherein the cutters arepositioned to minimize an imbalance force on the bit or a difference inwork rate between cutters on the bit.
 27. The drill bit of claim 19,wherein cutters along a blade are arranged to form a helix angle of lessthan 5°.
 28. The drill bit of claim 27, wherein cutters along the bladeare arranged to form a helix angle of 2° or less.
 29. The drill bit ofclaim 19, wherein at least one of the cutters comprises a bevel about atop periphery thereof, and wherein the bevel has width of at least about0.012 inches and is at an angle of around 45° from a side surface of thecutter.
 30. The drill bit of claim 19, wherein a space between frontfaces of a majority of adjacent cutters on the cutting face is about0.04 inches or less.
 31. The drill bit of claim 30, wherein at leastsome of the cutters positioned on the blades have an exposed substratelength of about 9 mm or less.
 32. The drill bit of claim 19, wherein atleast some of the cutters have a diameter of at least about 19 mm. 33.The drill bit of claim 19, wherein the cutter extent from thecorresponding blade front face is less than or equal to about 0.06inches.
 34. The drill bit of claim 33, wherein a majority of the cuttersare arranged substantially flush with blade front faces.
 35. The drillbit of claim 1, wherein the bit comprises less than 8 blades.
 36. Thedrill bit of claim 19, wherein at least one of the cutters comprise atable of ultrahard material integrally formed with a carbide substratecomprising tungsten carbide particles formed with a metallic binder, andthe substrate comprises a binder content of 12% by weight or less, ahardness of at least about 90 Ra, and a tungsten carbide content of atleast about 88% by weight.
 37. The drill bit of claim 36, wherein thesubstrate has an average carbide particle size of about 3 microns orless.
 38. The drill bit of claim 36, wherein the substrate furthercomprises ultrahard particles impregnated in the substrate.
 39. Thedrill bit of claim 36, wherein a coating is disposed on at least aportion of the substrate and the coating comprises the ultrahardparticles.
 40. The drill bit of claim 19, wherein at least one of thecutters comprises a polycrystalline diamond body bonded to a substrateand the polycrystalline diamond body is partially or entirely thermallystable.
 41. The drill bit of claim 1, wherein the drill bit furthercomprises at least one gage pad disposed along a side of the bit bodyhaving a circumferential width of at least about 2 inches or is arrangedto provide a total gage pad with about the periphery of the bit bodygreater than or equal to about 30% of the circumference of the bit. 42.The drill bit according to claim 1, wherein the drill bit furthercomprises at least one gage pad disposed along a side of the bit bodyand a plurality of rounded wear-resistant elements are aligned along asurface of the at least one gage pad proximal a leading edge or atrailing edge to provide rounded wear resistant protection.
 43. Thedrill bit of claim 42, wherein the wear resistant elements compriseelements selected from the group consisting essentially of thermallystable polycrystalline diamond elements, polycrystalline diamondelements, and grit hot-pressed inserts.
 44. The drill bit of claim 42,wherein a plurality of wear resistant elements are additionally disposedalong a surface of the gage pad between the leading and trailing edgesand comprise diamond enhanced inserts or TSP elements having diametersof at least about 13 mm.
 45. The drill bit of claim 44, wherein diamondenhanced inserts cover at least about 20% of the surface area of thegage pad.
 46. The drill bit of claim 44, wherein wear resistant elementscover at least about 50% of the outer surface of the gage pad.
 47. Thedrill bit of claim 45, wherein the diamond enhanced inserts havesubstrate lengths of at least about 13 mm and at least a portion of thesubstrate is embedded in the gage pad.
 48. The drill bit of claim 42,wherein the wear resistant elements are positioned proximal the leadingedge and arranged to provide a wear resistant barrier along the leadingedge that spans at least 75% of the gage pad length.
 49. The drill bitof claim 42, wherein the wear resistant elements are axially alignedalong their longitudinal axes forming a rounded, substantiallycontinuous and wear-resistant portion of the gage pad.
 50. The drill bitof claim 42, wherein wear resistant elements are also disposed proximala bottom edge and a top edge of the gage pad.
 51. The drill bit of claim1, wherein the drill bit further comprises at least one gage paddisposed along a side of the bit body, and wherein the at least one gagepad is slanted at an angle with respect to the longitudinal axis of thebit.
 52. The drill bit according to claim 1, wherein at least oneback-reaming element is positioned along a surface of the bit toback-ream formation in a path of the bit when the bit is pulled from awellbore.
 53. The drill bit of claim 1, wherein the drill bit comprisesa plurality of heel surfaces each having at least one back reamingelement disposed along the heel surface.
 54. The drill bit of claim 53,wherein the back reaming elements comprise PDC cutters having a diameterof at least about 13 mm.
 55. The drill bit of claim 1, furthercomprising fluid ports disposed in the bit body and oriented to directfluid towards a center of a corresponding fluid channel or away from acorresponding blade front face.
 56. The drill bit of claim 1, furthercomprising a plurality of fluid ports generally disposed between theblades wherein a number of fluid ports is greater than the number ofblades.
 57. The drill bit of claim 1, wherein the drill bit furthercomprises a fluid port and the fluid port comprises a diffuser nozzle.58. The drill bit of claim 1, wherein a coating of ultrahard material isapplied to a portion of the bit body by chemical vapor deposition.
 59. Amethod for drilling an earth formation, comprising: Providing a drillbit according to claim 1; and rotating the drill bit to form a wellbore.60. A method of manufacturing a drill bit comprising: forming a bit bodyhaving a cutting face and a side portion, the bit body comprisingcarbide matrix material; and forming a plurality of blades azimuthallyspaced about the cutting face; wherein at least one of the plurality ofblades is configured such that at least a portion of said blade has awider blade base than a blade top in the axial direction and at least aportion of the surface of said blade top comprises an ultrahard materialimpregnated therein.